Inhibitive divalent wellbore fluids, methods of providing said fluids, and uses thereof

ABSTRACT

A wellbore fluid includes an aqueous fluid, a viscosifer, a stabilizer agent, and a lubricant. The aqueous fluid is an inhibitive divalent fluid. A method of preparing the divalent wellbore fluid are provided or formulated, includes methods produce the divalent wellbore fluids, and methods inject or circulate the inhibitive divalent wellbore fluids into a wellbore or borehole provided in a formation and/or into a reservoir of the formation.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a divisional application of U.S. Pat. ApplicationNo. 16/882,681, filed May 25, 2020, which claims the benefit of, andpriority to, U.S. Provisional Pat. Application No. 62/852,310, filed onMay 24, 2019. Each of the above applications is incorporated herein byreference in its entirety.

FIELD OF THE DISCLOSURE

The present disclosure is directed to inhibitive divalent wellborefluids, methods of providing or producing the inhibitive divalentwellbore fluids and/or methods of using the inhibitive divalent wellborefluids. In embodiments, the inhibitive divalent wellbore fluids maycomprise at least one aqueous base fluid, one or more viscosifier agentsor viscosifiers, one or more stabilizer agents or stabilizers and/or oneor more lubricating agents or lubricants.

BRIEF DESCRIPTION OF THE DRAWINGS

The foregoing and other features of the present disclosure will becomemore fully apparent from the following description and appended claims,taken in conjunction with the accompanying drawings. Understanding thatthese drawings depict several embodiments in accordance with thedisclosure and are, therefore, not to be considered limiting of itsscope, the disclosure will be described with additional specificity anddetail through use of the accompanying drawings.

FIG. 1 is a digital photograph of a first core sample beforeexperimental testing was conducted in accordance with embodimentsdisclosed herein.

FIG. 2 is a digital photograph of a second core sample beforeexperimental testing was conducted in accordance with embodimentsdisclosed herein.

FIGS. 3-5 are digital photographs of a thin section cut from the firstcore sample in accordance with embodiments disclosed herein.

FIGS. 6-8 are digital photographs of a thin section cut from the secondcore sample in accordance with embodiments disclosed herein.

FIG. 9 is digital photographs of the thin section cut of the first coresample initially dry in the left-side photograph and finally dry afterlong-term exposure to freshwater in the right-side photograph inaccordance with embodiments disclosed herein.

FIG. 10 is digital photographs of the thin section cut of the secondcore sample initially dry in the left-side photograph and finally dryafter long-term exposure to freshwater in the right-side photograph inaccordance with embodiments disclosed herein.

FIG. 11 is digital photographs of the thin section cut of the first coresample initially dry in the left-side photograph and finally dry afterlong-term exposure to the produced/formation water in the right-sidephotograph in accordance with embodiments disclosed herein.

FIG. 12 is digital photographs of the thin section cut of the secondcore sample initially dry in the left-side photograph and finally dryafter long-term exposure to the produced/formation water in theright-side photograph in accordance with embodiments disclosed herein.

FIG. 13 is digital photographs of the thin section cut of the first coresample initially dry in the left-side photograph and finally dry afterlong-term exposure to the present divalent wellbore fluid comprisingproduced/formation water in the right-side photograph in accordance withembodiments disclosed herein.

FIG. 14 is digital photographs of the thin section cut of the first coresample initially dry in the left-side photograph and finally dry afterlong-term exposure to the present divalent wellbore fluid comprisingproduced/formation water in the right-side photograph in accordance withembodiments disclosed herein.

FIG. 15 is a digital photograph of the present divalent wellbore fluidafter being hot rolled with at least one lubricant in accordance withembodiments disclosed herein.

FIG. 16 is digital photographs showing top and side views, respectively,of a production water mixed with a viscosifier.

FIG. 17 is a graph of coefficient of friction values for wellbore fluidsin accordance with embodiments disclosed herein.

DETAILED DESCRIPTION

In the following detailed description, reference is made to theaccompanying drawings, which form a part hereof. The illustrativeembodiments described in the detailed description, examples and drawingsare not meant to be limiting and are for explanatory purposes. Otherembodiments may be utilized, and other changes may be made, withoutdeparting from the spirit or scope of the subject matter presentedherein. It will be readily understood that the aspects of the presentdisclosure, as generally described herein, set forth in the examplesand/or illustrated in the drawings, may be arranged, substituted,combined, and designed in a wide variety of different configurations,each of which are explicitly contemplated and made part of thisdisclosure.

The present disclosure is generally drawn to inhibitive divalentwellbore fluids, methods of providing or producing the inhibitivedivalent wellbore fluids and/or methods of using the inhibitive divalentwellbore fluids. Hereinafter, the inhibitive divalent wellbore fluidsmay be referred to as divalent wellbore fluids and/or may comprise atleast one aqueous base fluid, one or more viscosifier agents orviscosifiers, one or more stabilizer agents or stabilizers and/or one ormore lubricating agents or lubricants. In embodiments, the divalentwellbore fluids may be at least one high-density divalent wellborefluid, at least one low-density divalent wellbore fluid and/or acombination thereof and the one or more stabilizer agents or stabilizersmay be at least one thermal stabilizer agent or stabilizer. Inembodiments, the methods may comprise injecting, pumping or circulatingthe divalent wellbore fluids into a wellbore, a borehole and/or areservoir of a formation.

The divalent wellbore fluids disclosed herein (hereinafter “the presentdivalent wellbore fluid”) may be a wellbore fluid, such as, for example,a drilling fluid, a cementing fluid, a completion fluid, a packingfluid, a work-over (repairing) fluid, a stimulation fluid, a wellkilling fluid, a spacer fluid, a drill-in fluid and/or a combinationthereof. In embodiments, the present divalent wellbore fluid isconfigured or adapted for pumping, injecting or circulating into awellbore or borehole of a well provided in a formation and/or areservoir of the formation. In embodiments, the present divalentwellbore fluid is a drilling fluid, such as, for example a reservoirdrill-in fluid (hereinafter “RDF”) which may be configured or adaptedfor pumping, injecting or circulating into a reservoir or reservoirzone/area accessible via the wellbore or borehole of the well providedin the formation.

In embodiments, the present divalent wellbore fluid may comprise anaqueous fluid or solution. The aqueous fluid or solution may be a basefluid, such as, for example, a water-based fluid, a brine-based fluid ora combination thereof. The present divalent wellbore fluid may have anaqueous and/or brine fluid as the base liquid or the base fluid. In someembodiments, the present divalent wellbore fluid may have a brine baseliquid or fluid. A majority of the present divalent wellbore fluid maycomprise the aqueous fluid or solution. For example, the aqueous fluidmay present in the present divalent wellbore fluid at a concentrationranging from at least about 50% to about 100%, from about 60% to about99%, from about 70% to about 99% or from about 95% to about 99% byweight of the total divalent wellbore fluid.

In embodiments, the present divalent wellbore fluid, being formulated asa RDF, may have a divalent brine base liquid or fluid configured forpumping, injection or circulation into the reservoir or reservoirzone/area of the well. In other examples, the present divalent wellborefluid may be a water-based drilling fluid that may utilize at least onedivalent brine as the base fluid along with one or more viscosifieragents without or excluding biopolymers. Thus, the present divalentwellbore fluid may be, in embodiments, a divalent RDF that is abiopolymer-free brine base RDF for use in or with divalent brines and/orconfigured for improved or optimized reservoir production. In anembodiment, the present divalent wellbore fluid may be a water emulsionRDF configured or adapted for use as a completion fluid.

In embodiments, the aqueous fluid or solution of the present divalentwellbore fluid may include at least one of fresh water, sea water,brine, mixtures of water and water-soluble organic compounds andmixtures thereof. For example, the aqueous fluid or solution may beformulated with mixtures of desired salts in fresh water. Such salts mayinclude, but are not limited to alkali metal chlorides, hydroxides, orcarboxylates, for example. In various embodiments of the presentdivalent wellbore fluid, the brine may include seawater, aqueous fluidsor solutions wherein the salt concentration is less than that of seawater, or aqueous solutions wherein the salt concentration is greaterthan that of sea water. Salts that may be found in seawater include, butare not limited to, sodium, calcium, sulfur, aluminum, magnesium,potassium, strontium, silicon, lithium, and phosphorus salts ofchlorides, bromides, carbonates, iodides, chlorates, bromates, formates,nitrates, oxides, and fluorides. Salts that may be incorporated in abrine include any one or more of those present in natural seawater orany other organic or inorganic dissolved salts. Additionally, brinesthat may be used in the present divalent wellbore fluid may be naturalor synthetic, with synthetic brines tending to be much simpler inconstitution. In one embodiment, the density of the present divalentwellbore fluid may be controlled by increasing the salt concentration inthe brine (up to saturation). As a result, the present divalent wellborefluid may be a high-density or low-density wellbore fluid or RDF. Inparticular embodiments, a brine may include halide or carboxylate saltsof mono- or divalent cations of metals, such as cesium, potassium,calcium, zinc, and/or sodium.

In several embodiments, the present divalent wellbore fluid may be abiopolymer-free low-density divalent RDF. Such biopolymer-freelow-density divalent RDF may comprise a divalent brine base fluid and/orbe utilized for or during fluid applications requiring low brinedensities. In embodiments, the low brine densities may range from about1.0 to about 1.5 g/cm³, from about 1.1 to about 1.4 g/cm³, or from about1.13 to about 1.30 g/cm³.

In other embodiments, the present divalent wellbore fluid may be abiopolymer-free High-density divalent RDF. Such biopolymer-freehigh-density divalent RDF may comprise a divalent brine base fluidand/or be utilized for or during fluid applications requiring high brinedensities. In embodiments, the high brine densities may be up to about3.0 g/cm³, up to about 2.5 g/cm³, or up to about 2.1 g/cm³. In otherembodiments, the high brine densities may range from about 10 lbm/galUSto about 20 lbm/galUS, from about 11 lbm/galUS to about 18 lbm/galUS, orfrom about 11.5 lbm/galUS to about 17.0 lbm/galUS. Moreover, thebiopolymer-free high-density divalent RDF may exhibit thermal stabilityup to about 400° F., up to about 350° F., or up to about 300° F.

The present divalent wellbore fluid may provide a biopolymer-free fluidcomprising divalent-brine base fluids which may further comprisebridging agents with a controlled particle-size distribution. As aresult, the present divalent wellbore fluid may exhibit or achieveimproved low equivalent circulating densities, improved low frictionfactors and improved compatibility with complex completions, such as,for example, openhole gravel packs.

In embodiments, the base fluid of the present divalent wellbore fluidmay be brine produced from a well or field formed in a formation(hereinafter “produced brine base fluid”). The produced brine base fluidof the present divalent wellbore may comprise at least one of thefollowing ions selected from the group consisting of a bromide ion, acalcium ion, a sodium ion, a magnesium ion, a potassium ion, an ironion, a chloride ion, a nitrate ion and a sulfate ion. Moreover, theproduced brine base fluid may comprise one or more metals or heavymetals selected from the group consisting of As, Cd, Cr, Cu, Mn, Mo, Ni,Pb, Se, V and Zn. The present disclosure should not be deemed as limitedto a specific embodiment of the ion and/or the heavy metal that may bepresent in the produced brine base fluid.

The present divalent wellbore fluid may comprise at least one water orbrine base fluid (hereinafter “the base fluid”), at least one primaryviscosifier agent or viscosifier (hereinafter “the at least one primaryviscosifier”), at least one secondary viscosifier agent or viscosifier(hereinafter “the at least one secondary viscosifier”), at least onetemperature stabilizing agent or temperature stabilizer (hereinafter“the at least one stabilizer”) and/or at least one lubricating agent orlubricant (hereinafter “the at least one lubricant”).

The base fluid of present divalent wellbore fluid may be a water basefluid or a brine base fluid, such as, for example, a divalent brine basefluid or a divalent brine fluid loss control pill. In embodiments, thedensity of the base fluid may be from about 9.5 to about 10 lbm/gal,from about 9.6 to about 9.9 lbm/gal, or from about 9.7 to about 9.8lbm/gal. A majority of the present divalent wellbore fluid may comprisethe base fluid. In other words, the base fluid may be present in thepresent divalent wellbore fluid at a concentration of at least about50%, at least about 75%, at least about 90%, at least about 95%, atleast about 97% or at least about 99% by weight of the total divalentwellbore fluid. In other embodiments, the base fluid may be present inthe present divalent wellbore fluid at a concentration ranging from atleast 0.95 bbl, at least 0.97 bbl or at least 0.99 bbl.

Exemplary primary and secondary viscosifer agents or viscosifiers mayinclude those disclosed in U.S. Pat. Nos. 6,300,286 and 6,391,830 whichare hereby incorporated by reference, in their entirety.

The at least one primary viscosifier may be at least one starchderivative. In embodiments, the at least one starch derivative may be,for example, a high-molecular-weight, branched-chain starch derivative.The at least one starch derivative may have a specific gravity of atleast about 1.4, no more than 1.6, or about 1.5 and/or may be at leastpartially soluble in water or brine. In embodiments, the at least onestarch derivative may be utilized in calcium chloride, calcium bromide,zinc bromide and divalent field brines, and the at least one primaryviscosifier may control filtrate loss in the present divalent wellborefluid and/or be utilized as a fluid loss additive. In embodiments, thewater/brine solubility of the at least one starch derivative may be atleast about 90%, at least about 95%, or about 100%.

In embodiments, the at least one primary viscosifier may be present inthe present divalent wellbore fluid at a concentration ranging fromabout 20 to about 40 kg/m³, from about 21 to about 35 kg / m³, or fromabout 22.8 to about 34. 2 kg /m³. In other embodiments, the at least oneprimary viscosifier may be present in the present divalent wellborefluid at a concentration ranging from about 5 to about 15 ppb, fromabout 6 to about 12 ppb, from about 7 to about 10 ppb, or from about 8to about 9 ppb.

The at least one secondary viscosifier may be at least one magnesiumcompound. In embodiments, the at least one magnesium compound may be,for example, a fine-particle-size, highly reactive magnesium compoundhaving a specific gravity from at least about 3.40, at least about 3.5,no more than about 3.7, no more than about 3.6, or about 3.56. Inembodiments, the at least one secondary viscosifier may have a slightwater solubility of less than about 5%, less than about 2%, or less thanabout 1%. In embodiments, the at least one secondary viscosifier may beutilized as and/or may be a pH control agent and/or may synergisticallyinteract with the at least one primary viscosifier to enhancelow-shear-rate viscosities of the biopolymer-free low-density divalentRDF and/or biopolymer-free high-density divalent RDF.

The at least one secondary viscosifier may be present in the presentdivalent wellbore fluid at a concentration range from about 0.5 to about7 kg/m³, from about 0.6 to about 6.5 kg/m³, or from about 0.7 to about6.4 kg/m³. he at least one secondary viscosifier may be present in thepresent divalent wellbore fluid at a concentration range from about 0.5to about 5 ppb, from about 0.75 to about 4 ppb, from about 1 to about 3ppb, or from about 1.5 to about 2 ppb.

In embodiments, the at least one primary viscosifier and the at onesecondary viscosifier may interact in a surprising and unexpectedsynergistic manner to enhance, elevate and/or improve low shear-rateviscosity of the present divalent wellbore fluid.

The at least one lubricant may be soluble in the base fluid of thepresent divalent wellbore fluid. In embodiments, the at least onelubricant is a water-soluble brine lubricant. The at least one lubricantmay be a wellbore fluid or mud lubricant that may reduce torque, dragand friction in wellbore fluids or RDFs. The at least one lubricant maybe present in the present divalent wellbore fluid at a concentrationranging to no more than 5%, from about 0.6 to about 4%, from about 0.6to about 3.5%, or from about 2 to about 3% by weight of the totaldivalent wellbore fluid. For example, the lubricant can comprise analkyl or aryl that may be in the form of an ester or ether. Thelubricant may comprise an alcohol, such as glycol or isopropyl alcohol.In an embodiment, the lubricant may be an ester in a base fluid withisopropyl alcohol or a polyglycol.

The at least one stabilizer may be a blend of polymeric alkalinematerials and/or may buffer the pH of the present divalent wellborefluid in a pH region of from about 9 to about 12 or from about 10 toabout 11. As a result, the present divalent wellbore fluid may reduceand/or minimize hydrolysis and/or reduce breakdown rates ofpolysaccharides and cellulosics by preventing chemical reactionscreating thermal degradation of the polymers. In embodiments, the blendof polymeric alkaline materials may have a specific gravity from about1.0 to about 1.02, a flash point of at least about 200° F. or at leastabout 205° F., and a boiling point of at least about 330° F. or about340° F.

The at least one stabilizer may be present in the present divalentwellbore fluid at a concentration range of no greater than 0 ppb, fromabout 1 to above 5 ppb, from about 1.5 to about 4.5 ppb, or from about 2to about 4 ppb. For example, the at least one stabilizer may be obtainedfrom the product PTS-200 sold by M-I SWACO.

The present divalent wellbore fluid may exhibit and/or achieve one ormore fluid properties or mud properties. In embodiments, the one or morefluid or mud properties may comprise one or more values and/or valueranges associated with the Bingham-plastic model, such as, for example,plastic viscosity (hereinafter “PV”) values and/or yield point(hereinafter “YP”) values.

In embodiments, the PV value exhibited or achievable by the presentdivalent wellbore fluid may range from at least about 2.5 to no morethan about 30, from about 4 to about 25, from about 5 to about 22, fromabout 7 to about 21 or from about 8 to about 16. In other embodiments,the PV value exhibited or achievable by the present divalent wellborefluid may range from at least about 2.75 to no more than about 10.5,from about 4.5 to about 7.5, from about 5.0 to about 7 or from about 5.5to about 7.

In embodiments, the YP value exhibited or achievable by the presentdivalent wellbore fluid may range from at least about 2.5 to no morethan about 50, from about 5 to about 40, from about 10 to about 30, fromabout 12 to about 26 or from about 19 to about 25. In other embodiments,the YP value exhibited or achievable by the present divalent wellborefluid may range from at least about 1.5 to no more than about 35, fromabout 3 to about 25, from about 4 to about 12, from about 5 to about 10or from about 7 to about 10.

The one or more fluid or mud properties may also comprise coefficient offriction, µ, values or value ranges exhibited or achievable by thepresent divalent wellbore fluid. The coefficient of friction, µ, valuesmay be measured at 60 rpm and 150 psi. In embodiments, the coefficientof friction, µ, exhibited or achievable by the present divalent wellborefluid may range from about at least 0.01 to no more than 0.20, fromabout 0.03 to about 0.15, from about 0.05 to about 0.14 or from about0.11 to about 0.14.

One or more conventional methods may be used to prepare the presentdivalent wellbore fluid in a manner analogous to those normally used, toprepare conventional aqueous- or water-based wellbore fluids. In oneembodiment, a desired quantity of aqueous base fluid and a suitableamount of one or more of the at least one primary viscosifier, the atleast one secondary viscosifier, the at least one stabilizer and/or theat least one lubricant, as described above, are mixed together withcontinuous mixing. In an embodiment, an emulsion divalent wellbore fluidmay be formed by vigorously agitating, mixing, or shearing the presentdivalent wellbore fluid in the presence of one or more emulsifyingagents and/or additives or emulsifiers.

In yet another embodiment, the present divalent wellbore fluid may beused alone or in combination with one or more conventional or additionaladditives. The additional additives, that may be included in the presentdivalent wellbore fluid, include, for example, wetting agents,organophilic clays, viscosifiers, fluid loss control agents,surfactants, dispersants, interfacial tension reducers, pH buffers,mutual solvents, thinners, thinning agents, and cleaning agents. Theaddition of such additives should be well known to one of ordinary skillin the art of formulating wellbore fluids and muds or RDFs.

In embodiments, the methods disclosed herein may comprise preparing thepresent divalent wellbore fluid by mixing or formulating at least oneaqueous base fluid, the at least one primary viscosifier, the at leastone secondary viscosifier, the at least one stabilizer and/or the atleast one lubricant, as described above. After mixing or formulating thepresent divalent wellbore fluid, the method may further comprisepumping, injecting or circulating the present divalent wellbore fluidinto a wellbore or borehole of well formed in a formation and/or into areservoir area/zone of the formation. In embodiments, the method mayfurther comprise retrieving the present divalent wellbore fluid from thewellbore, borehole and/or reservoir area/zone of the formation.Moreover, the retrieved divalent wellbore fluid may be filtered,recycled and/or treated for subsequent use as a wellbore fluid or RDF.

In embodiments, the methods disclosed herein may comprise preparing thepresent divalent wellbore fluid by mixing or formulating at least onecloud point polyglycol based shale stabilizer. Clouding polyglycols whenused in conjunction with inhibitive salts such as, calcium chloride orpotassium chloride, can be used in water based systems to control watersensitive shales by minimizing the amount of water invasion intopre-existing fractures. The clouding polyglycol chemistry is selectedbased on the expected downhole temperature and base fluid salinity toensure adequate clouding properties for maximum shale stabilization.When the fluid environment is above the cloud point, the polyglycolbecomes insoluble in water and penetrates the shale which plugsmicropores and minimizes the amount water uptake from the shale.Additional glycol based stabilizers in which glycol is the carrier fluidfor a predispersed gilsonite suspension for additional shale stability.

EXAMPLES

The present disclosure and proposals are further illustrated by thefollowing specific examples, and these examples are provided toillustrate the disclosure and proposals, and do not unnecessarily limitthem.

1. Produced Brine Base Fluid Composition for the Divalent Wellbore Fluid

A suitable produced brine base fluid for the present divalent wellborefluid was produced from a well or field (hereinafter “produced brine” or“field brine”). The produce brine base fluid was analyzed via IonAnalysis - IC, chloride/bromide titration and ICP analysis to determinethe salt and metal compositions therein. The determined salt and metalcompositions are set forth in Tables 1 and 2 respectively.

TABLE 1 Regular salt analysis results: Produced brine for presentdivalent wellbore fluid Bromide 0.30 w% Calcium 0.88 w% Sodium 7.38 w%Magnesium 630 mg/Kg Potassium 0.74 w% Iron 0.1 mg/Kg Chloride 13.26 w%Nitrate <1 mg/Kg Sulfate <1 mg/Kg

TABLE 2 Heavy metal results: Produced brine for present divalentwellbore fluid As (mg/Kg) <0.01 Cd (mg/Kg) <0.01 Cr (mg/Kg) <0.01 Cu(mg/Kg) 0.1 Mn (mg/Kg) 7.1 Mo (mg/Kg) 0.2 Ni (mg/Kg) 0.1 Pb (mg/Kg)<0.01 Se (mg/Kg) <0.01 V (mg/Kg) 0.02 Zn (mg/Kg) 0.3

2. Long-Term Immersion Stability Test on Formation Core Sections

Long-term immersion stability testing was conducted on core sections ofa shale formation to provide and/or produce stability testing results.Those stability testing results were analyzed to identify and/ordetermine suitability of the present divalent wellbore fluid to beutilized as RDFs in shale formations. Analysis of the stability testingresults and shale formation included: mineralogy and reactivity valuesvia x-ray diffraction (hereinafter “XRD”) and cation exchange capacity(hereinafter “CEC”); core descriptions; and petrographic analysis ofcore sections. Based on the rock properties and core section quality,long-exposure immersion testing was carried out for shale stabilitytesting.

The core sections tested comprised a Core Slab 1 and Core Slab 2(collectively referred to hereinafter as “Core Slabs 1 and 2”). CoreSlab 1 was collected or taken from a formation depth of about10,572.7.00 to about 10,573 \.0 feet deep, and Core Slab 2 was collectedor taken from a formation depth of about 10,584.4.00 to about 10,585 \.0feet deep. The Core Slabs 1 and 2 had the following characteristics.

First, the Core Slabs 1 and 2 were a dark black, organic-rich shale, andthe Core Slabs 1 and 2 were very hard, well-compacted, andwell-laminated (see FIGS. 1 and 2 ). The Core Slabs 1 and 2 each arrivedin 2-3 sections, broken parallel to the bedding plane direction.Pre-existing fractures are present and mainly parallel to the beddingplane direction and laminations. The Core Slabs 1 and 2 contained about7-12% clay minerals. Illite was the dominate clay mineral present inCore Slab 2, while Illite and Smectite were approximately equal inproportion in Core Slab 1. A majority of the mineral composition camefrom Quartz. The Core Slabs 1 and 2 contained about 2-3% Pyrite in thepieces submitted for x-ray diffraction, but Pyrite-rich layers arevisible within the section and may contain significantly higher amounts.The organic content of the Core Slabs 1 and 2 was about 7-13%. Piecesthat were submitted for XRD and CEC were representative of an “average”mineralogy of the analyzed samples, but the Core Slabs 1 and 2 may havecontained layers with higher amounts of certain minerals (clay minerals,quartz, pyrite, etc.).

Based on the analyzed characteristics of the Core Slabs 1 and 2,long-term immersion testing was performed on the Core Slabs 1 and 2 withthree different testing fluids. The three testing fluids were freshwater (hereinafter “the reference fluid”), produced/formation water orbrine (hereinafter “produced/formation water”) and the present divalentwellbore fluid comprising the produced/formation water.

A. Mineralogy (XRD) and Cation Exchange Capacity (CEC)

Results of Semi-Quantitative XRD and Methylene Blue Test of the CoreSlabs 1 and 2 are set forth below in Table 3.

TABLE 3 Mineralogy Data (%wt): 10572.7-10573.0 10564.4-10565.0 Smectite*3 1 Illite 4 11 Calcite 1 9 Quartz 75 43 Dolomite 2 9 Feldspars 5 12Pyrite 3 2 Organics** 7 13 CEC, meq/100 gr 3 1 *Include Illite/mixedlayers. **Organics determined by TGA

The results of the XRD analysis indicated that the sample is primarilycomposed of Quartz (~43-75%). Illite is the predominate clay mineral inCore Slab 2, but Smectite is also present. In Core Slab 1, the clayminerals are present in approximately equal proportions. The higheramount of Illite compared to the low amount of Smectite indicates thatthe sample may have undergone stronger diagenesis and thermalalteration; this is consistent with other core features. The samplecontains a high amount of Pyrite, which may suggest that the shale couldbe deposited in a strong anoxic environment. Organics constitute about7-13% of the sample composition. Based on the CEC results, the samplehas low potential for chemical reactivity, such as, for example, a lowreactive shale: CEC < 10 meq/100 gr.

B. Thin Sections

Thin section observations were conducted to collect and/or produceinformation determine and/or understand the mineralogy, texture,structure, and fracturing of the rock samples of the Core Slabs 1 and 2.This information established a base to evaluate the potential effects ofthree test fluids on the stability of the formation.

The sample of Core Slab 1 was set in blue dyed epoxy before cutting intothe thin section. FIG. 3 shows the thin section cut from Core Slab 1.

FIG. 4 shows that the thin section sample of Core Slab 1 was very darkin color. The dark color was attributed to the high amount of pyrite andorganic material. Bright white spots were mostly quartz grains. Darkmaterial was clay minerals, pyrite, and insoluble organics. Two thinfractures (blue) were visible parallel to the bedding plane andlaminations. The sample of Core Slab 1 was well-laminated andwell-compacted.

FIG. 5 shows the same thin section view of Core Slab 1 as shown in FIG.4 , but with reflective light instead of polarized light. The reflectedlight allowed for pyrite to be seen. In the polarized light view (seeFIG. 4 ), pyrite was dark black. In the reflected light, pyrite wasbright white (as visible in FIG. 5 ).

The sample of Core Slab 2 was set in blue dyed epoxy before cutting intothe thin section. FIG. 6 shows the thin section cut from Core Slab 2.

FIG. 7 shows that the thin section sample of Core Slab 2 was very darkin color. The dark color was attributed to the high amount of pyrite andorganic material. Bright white spots were mostly quartz grains. Darkmaterial was clay minerals, pyrite, and insoluble organics. One thinfracture (blue) were visible parallel to the bedding plane andlaminations. The sample was well-laminated and well-compacted.

FIG. 8 shows the same thin section view of Core Slab 2 as shown in FIG.7 , but with reflective light instead of polarized light. The reflectedlight allowed for pyrite to be seen. In the polarized light view (seeFIG. 7 ), pyrite was dark black. In the reflected light, pyrite wasbright white (as shown in FIG. 8 ).

C. Stability Testing Procedures i. Immersion Test Steps:

-   cutting the rock sample into comparable pieces, approximately equal    in size. A diamond blade for dry cutting application is used to    avoid any contact of the rock with fluid before testing;-   selecting the front side of the sample and remove the mark of the    blade using sand paper;-   photographing the samples before exposure to the fluids    (Initial-Dry);-   immersing the samples in the fluids in containers for 2 weeks at    room temperature;-   taking photographs of the samples during the fluid exposure (for    clear fluids);-   removing the samples from the containers and let the sample dry at    room temperature; and-   taking a final photograph.

ii. Fluids Tested:

-   freshwater;-   produced/formation water; and-   present divalent wellbore fluid comprising produced/formation water.

iii. Test Data/Information Collected:

FIG. 9 shows, prior to fluid exposure to the freshwater, somepre-existing fracture planes were visible approximately parallel to thebedding laminations. After two (2) weeks of fluid exposure to the freshwater, pre-existing fractures were not enlarged or propagated.Development of new fractures was not evident. Minor precipitation wasformed along pre-existing fracture surfaces after samples were removedfrom the fluids and allowed to dry at room temperature.

FIG. 10 shows, prior to fluid exposure to the freshwater, somepre-existing fracture planes were visible approximately parallel to thebedding laminations. After two (2) weeks of fluid exposure to thefreshwater, pre-existing fractures were not enlarged or propagated.Development of new fractures was not evident. Minor precipitation wasformed along pre-existing fracture surfaces after samples were removedfrom the fluids and allowed to dry at room temperature.

FIG. 11 shows, prior to fluid exposure to the produced/formation water,some pre-existing fracture planes were visible approximately parallel tothe bedding laminations. After two (2) weeks of fluid exposure to theproduced/formation water, pre-existing fractures were not enlarged orpropagated. Development of new fractures was not evident.

FIG. 12 shows, prior to fluid exposure to the produced/formation water,some pre-existing fracture planes were visible approximately parallel tothe bedding laminations. After two (2) weeks of fluid exposure to theproduced/formation water, pre-existing fractures were not enlarged orpropagated. Development of new fractures was not evident. Minorprecipitation was formed along pre-existing fracture surfaces aftersamples were removed from the fluids and allowed to dry at roomtemperature.

FIG. 13 shows, prior to fluid exposure to the present divalent wellborefluid comprising the produced/formation water, some pre-existingfracture planes were visible approximately parallel to the beddinglaminations. After two (2) weeks of fluid exposure the present divalentwellbore fluid comprising the produced/formation water, pre-existingfractures were not enlarged or propagated. Development of new fractureswas not evident.

FIG. 14 shows, prior to fluid exposure to the present divalent wellborefluid comprising the produced/formation water, some pre-existingfracture planes were visible approximately parallel to the beddinglaminations. After two (2) weeks of fluid exposure, pre-existingfractures were not enlarged or propagated. Development of new fractureswas not evident. Minor precipitation was formed along pre-existingfracture surfaces after samples were removed from the fluids and allowedto dry at room temperature.

iv. Immersion Test Results:

The immersion test results showed development and/or propagation offractures in hard and fissile shale core samples of Core Slabs 1 and 2,when the core samples were exposed to the three test fluids.Photographic documentation of the changes in the rock samples of CoreSlabs 1 and 2 in FIGS. 9-14 for comparative evaluation of the effects ofthe three test fluids.

TABLE 4 Results of Long-Exposure Immersion Testing Fluid ObservationsOverall Stability Freshwater No major change visible. Precipitationalong fracture planes after drying. Rock remained intact and stable.High Produced/Formation Water No major change visible. Precipitationalong fracture planes after drying. Rock remained intact and stable.High DIPRO (w/ Produced/Formation Water) No major change visible.Precipitation along fracture planes after drying. Rock remained intactand stable. High

Overall, the stability of the Core Slabs 1 and 2 is high in all threetesting fluids. No major change was observed (see Table 4). Someprecipitation after fluid testing and during the drying process wasobserved.

The Core Slabs 1 and 2 had low potential for chemical interaction andinstability after being exposed to the three testing fluids. However,because of the high volume of pre-existing fractures, minimizinginvasion and movement of the drilling fluid along fracture planes may becritical in order to maintain wellbore stability. No wettabilitymeasurement was available for the Core Slabs 1 and 2, but features (suchas high organic matter, oily surface) may suggest that the core islikely oil-wet. If it is oil-wet, the use of oil-based drilling fluidscould have more potential to invade and lubricate the fracture surfacescausing wellbore instability because of the low capillary entrancepressure. The use of the present divalent wellbore fluid, comprising theproduced/formation water or brine base fluid, reduces or lessen thepotential of the fluid invasion along pre-existing fracture planesbecause of the higher capillary entrance pressure.

v. Analysis of Produce/Formation Water

Atomic absorption analysis and Ion analysis - IC were utilized toexamine and determine the composition of the produced/formation watertesting fluids. The composition of produced/formation water testingfluids is set forth below in Table 5.

TABLE 5 Produced/formation water composition -01 Formation Brine -02Formation Brine Chloride 15.9 w/w% 15.1 w/w% Bromide ND ND Sodium 9.15w/w% 8.96 w/w% Potassium 8.264 mg/kg 5.678 mg/kg Calcium ND ND Magnesiu1.167 mg/kg 1.163 mg/kg Zinc 64 mg/kg 47 mg/kg Iron 52 mg/kg 42 mg/kg

vi. Present Divalent Wellbore Fluid Composition, Formulation andRheology

The present divalent wellbore fluid was formulated with theproduced/formation water as a point of reference as set forth belowTable 6, the rheology of the formulated divalent wellbore fluid is setforth in Table 7 and the tests involved with the rheology were the XRDtest, the CEC test, the TGA test and the Immersion test.

TABLE 6 Present divalent wellbore fluid formulation Formulation ProductConcentration Produced/Formation Water 350 mL Di-Trol 8 ppb Di-Balance1.5 ppb PTS-200 4 ppb

TABLE 7 Present divalent wellbore fluid rheology Rheology RPM BeforeHot-Rolling @ 235 F After Hot-Rolling @ 235 F 600 38 37 300 30 27 200 2623 100 21 18 6 10 9 3 8 8

3. Divalent Wellbore Fluid with Field Brine Formulations and Properties

A plurality of the present divalent wellbore fluids, namely, Examples1-14, comprising a field brine as the aqueous base fluid were formulatedas set forth below Tables 8-11. As shown in upper portions of Tables8-11, the Examples 1-14 comprise one or more components selected fromthe base fluid, the at least one primary viscosifier, the at least onesecondary viscosifier, the at least one stabilizer and/or the at leastone lubricant disclosed herein. The concentrations of the components arealso set forth in the upper portions of Tables 8-11. Moreover,characteristics or properties of formulations in Examples 1-14 are setforth in bottom portions of Tables 8-11 and identified as “MudProperties” therein.

TABLE 8 Formulations and properties of Examples 1-4 1 2 3 4 FormulationField Brine, bbl 1.0 0.99 0.99 0.99 Di-Trol. ppb 8.0 8.0 8.0 Di-Balance,ppb 1.0 1.0 1.0 PTS-200, ppb 4.0 4.0 Torq Free HD, % 3.0 3.0 MudProperties Initial Aged Initial Aged Initial Aged Initial Aged HeatAging Temp, °F 150 150 Heat Aging Hours 16 16 Static/Rolling R RRheology Temp, °F 120 120 120 600 rpm 15 35 30 300 rpm 10 27 20 200 rpm8 23 16 100 rpm 5 18 12 6 rpm 1 10 6 3 rpm 1 9 5 PV, cps 5 8 10 YP,lbs/100 ft² 5 19 10 10 Seconds Gel 1 9 5 10 Minutes Gel 1 11 7 APIFiltrate, mL 14.0 Coefficient of Friction, µ @ 60 rpm & 150 psi 0.030.05 0.11 0.13 0.03 0.03

TABLE 9 Formulations and properties of Examples 5-8. *5 6 7 8Formulation Field Brine, bbl 0.99 0.99 0.99 0.99 Di-Trol. ppb 9.0 9.09.0 9.0 Di-Balance, ppb 2.0 2.0 2.0 2.0 PTS-200, ppb 4.0 4.0 Torq FreeHD, % 3.0 3.0 Mud Properties Initial Aged Initial Aged Initial AgedInitial Aged Heat Aging Temp, °F 150 150 150 Heat Aging Hours 16 16 16Static/Rolling R R R Rheology Temp, °F 120 120 120 120 600 rpm 48 66 6752 300 rpm 36 45 53 39 200 rpm 30 36 49 34 100 rpm 23 26 41 17 6 rpm 1012 21 14 3 rpm 9 10 19 13 PV, cps 12 21 14 13 YP, lbs/100 ft″ 24 24 3926 10 Seconds Gel 10 10 19 13 10 Minutes Gel 13 13 21 15 API Filtrate,mL 12.0 >20.0 Coefficient of Friction, µ @ 60 rpm & 150 psi 0.11 0.130.03 0.03 0.13 0.14 0.03 0.03

TABLE 10 Formulations and properties of Examples 9 and 10. 9 10Formulation Field Brine, bbl 0.99 0.99 Di-Trol. ppb 8.0 8.0 Di-Balance,ppb 2.0 2.0 PTS-200, ppb 4.0 Mud Properties Initial Aged Initial AgedHeat Aging Temp, °F 150 150 Heat Aging Hours 16 16 Static/Rolling R RRheology Temp, °F 120 120 120 120 600 rpm 53 46 57 41 300 rpm 38 30 4127 200 rpm 31 24 35 21 100 rpm 25 18 28 16 6 rpm 12 8 17 9 3 rpm 11 7 168 PV, cps 15 16 16 14 YP, lbs/100 ft² 23 14 25 13 10 Seconds Gel 11 7 168 10 Minutes Gel 15 10 19 10 API Filtrate, mL 19.0 >30.0

TABLE 11 Formulations and properties of Examples 11-14. 11 12 **13 14Formulation Field Brine, bbl 0.99 0.99 0.99 0.99 Di-Trol. ppb 8.0 8.08.0 8.0 Di-Balance, ppb 1.5 1.5 1.5 1.5 PTS-200, ppb 2.0 4.0 ***SafeLube, % 0.6 Mud Properties Initial Initial Initial Initial Aged HeatAging Temp, ◦F 150 Heat Aging Hours 16 Static/Rolling R Rheology Temp,°F 120 120 120 120 120 600 rpm 23 45 41 29 34 300 rpm 16 34 31 21 23 200rpm 13 29 27 18 19 100 rpm 9 24 22 14 14 6 rpm 3 13 11 7 7 3 rpm 2 12 106 6 PV, cps 7 11 10 8 11 YP, Ibs/100 ft² 9 23 21 13 12 10 Seconds Gel 312 10 6 6 10 Minutes Gel 4 15 12 9 8 Coefficient of Friction, µ @ 60 rpm& 150 psi 0.07 0.12

The following remarks are associated with Tables 8-11 and/or Examples1-14:

-   Field Brine Results (MW: 9.8 ppg, pH: 6.8, Total Hardness: 18,920    mg/L, Chlorides: 165,000 mg/L, Ca²⁺: 2,880 mg/L, Iron in brine: <10    mg/L, Coefficient of Friction @ 60 rpm & 150 psi: 0.09 µ);-   *This sample was sheared 25 min longer, which is most likely why    rheology numbers are higher. (original sample was 8 ppb DI-TROL and    1 ppb DI-BALANCE - then added 1 ppb of each), all samples containing    TORQUE FREE HD exhibited greasy appearance;-   **Sample 13 was previously sample 12 (which already contained 2 ppb)    so an additional 2 ppb of PTS-200 was added to make a total of 4    ppb; and-   ***Coefficient of friction @ 60 rpm, & 150 psi for Field Brine and    0.6% Safe lube= 0.05 µ.

4. Divalent Wellbore Fluid with Produced Brine Formulations and theirProperties

This example studied a plurality of the present divalent wellborefluids, namely, Examples 15-24: each comprising a produced brine as theaqueous base fluid, mixed and/or formulated as set forth below in Table12. As shown in upper portion of Table 12, the Examples 15-24 compriseone or more components selected from the base fluid, the at least oneprimary viscosifier, the at least one secondary viscosifier, and/or theat least one stabilizer disclosed herein. The concentrations of thecomponents are also set forth in the upper portion of Table 12.Moreover, characteristics or properties of formulations in Examples15-24 are set forth in bottom portion of Table 12 and identified as“Mixing Procedure” therein. Regarding the “Mixing Procedure”, either aHamilton Beach mixer (hereinafter “HB Mixer”) or a Silverson Mixer(hereinafter “Silverson”) was utilized for Examples 15-24. Moreover, thetemperature during the mixing of Examples 15-24 was either roomtemperature (hereinafter “Room Temp”) or 120° F. (hereinafter “120°”).

TABLE 12 Formulations and properties of Examples 15-24. DivalentWellbore Fluids Comprising Produced Brine Base Fluids 15 16 17 18 19 2021 22 23 24 Brine Density 9.76 ppg 9.76 p pg 9.76 ppg 9.76 pp g 9.76 ppg 9.76 pp g 9.76 pp g 9.76 pp g 9.76 pp g 9.76 pp g DI-TROL 8 8 8 8 8 88 8 8 8 DI-BALAN 1.5 1.5 2 2 1.5 1.5 2 2 3 3 PTS-200 0 0 0 0 4 4 4 4 4 4Mixing Procedure Room Temp HB Mixer 120⁰ Silverson Room Temp HB Mixer120⁰ Silverson Room Temp HB Mixer 120⁰ Silverson Room Temp HB Mixer 120⁰Silverso Room Temp HB Mixer 120⁰ Silverso 600 14 15 17 20 15 22 21 26 1737 300 8.5 10 12 14 9.5 16 14 19 11 30 200 7 8 9 11 8 12 12 13 9 26 1005 6 7 9 6 10 10 11 6.5 24 6 2 3 3 4 3 5 4 5 3 12 3 1 2 2 3 2 4 3 4 2 11PV 5.5 5 5 6 5.5 6 7 7 6 7 YP 3 5 7 8 4 10 7 12 5 23

5. Divalent Wellbore Fluid with Production Water Formulations and theirProperties

This example studied a plurality of the present divalent wellborefluids, namely, Examples 15-24: each comprising a production water asthe aqueous base fluid, mixed and/or formulated as set forth below inTable 12.

This example also studied different samples of production water for useas the aqueous base fluid of the divalent wellbore fluids in Examples15-24.

The different samples of production water were submitted for ionsanalysis to determine compositions of each sample. The sample showingthe highest salinity and highest hardness was subsequently used as theaqueous base fluid to design or formulate the divalent wellbore fluid asa reservoir drilling fluid or RDF. The highest salinity may bedetermined based on, for example, chloride concentration, and thehardness may be determined based on, for example, calcium ionsconcentration.

The ENDURADRIL RDF fluid system (hereinafter “ENDURADRIL system”) wasselected based on its ability to efficiently perform in presence ofdivalent ions. Three different viscosifier agents, namely, POWERVIS,FLOVIS PLUS and DI-TROL (as discussed above) were assessed. Thesedifferent viscosifiers were selected in order to promote low pumppressure and very good hole cleaning at testing conditions.

FLO-VIS PLUS is a high yield, premium-grade, clarified xanthan gum.FLO-VIS PLUS is usable in RDFs and may produce elevated low-shear-rateviscosity (hereinafter “LSRV”) and high, but fragile, gel strengths.These properties associated with FLO-VIS PLUS provide superior holecleaning and suspension, improved hydraulics, reduced torque and drag,and assist in minimizing filtrate invasion. These properties maycontribute to improved drilling performance, reduced formation damageand lower overall well costs.

POWER VIS is a branched linear polymer usable in low salinity brines,such as, for example, KCl and NaCl brines. POWER VIS may provideexcellent lowend rheology with reduced overall pump pressures. As aresult, POWER VIS may be an available option for coiled tubingapplications.

The design and evaluation of the formulated ENDURADRIL systems wasperformed by assessing the rheological properties, coefficient offrictions and visual observations. The bottom hole temperature at 265°F. and sixteen (16) hours dynamic aged were parameters desired. Thisexample highlights the laboratory assessments undertaken in evaluatingthe ENDURADRIL systems and summarizes the results of said evaluation.The formulations of this example comprised 9.8 lb/gal of the ENDURADRILsystem and were differentiated by the concentrations and the types ofthe viscosifiers (i.e., DI-TROL, FLO-VIS PLUS and POWER VIS) includedtherein.

A. Water Composition

Production water samples were submitted for ion analysis to determinethe composition of each sample. Atomic Absorption Spectroscopy,Titration, Ion Chromatography analysis and ICPMS were methods used insaid analysis. Results were used to mix synthetic production waterutilized to build or formulate the ENDURADRIL systems. The water sample(hereinafter “WS”) listed as WS1 was selected as base fluid based onhigher calcium concentration ions present in its composition. Thesynthetic version of WS1 was used during the design process of theENDURADRIL systems. The final ENDURADRIL system formulation obtainedwith synthetic version of WS1 was then re-evaluated using othersproduction water samples to mitigate any issues. Table 13 showscomposition and properties of the production WSs utilized in thisexample.

TABLE 13 Composition and Properties of the Production Water Ion WS1 WS2WS3 WS4 WS5 WS6 Calcium 17400 12500 10100 15000 12000 16000 Magnesium1200 1100 630 210 200 180 Sodium 105500 95800 97200 67600 48400 108600Potassium 8700 4400 4400 4980 4450 10000 Strontium 1700 870 650 Barium0.79 3.7 0.1 Iron 0.1 0.1 0.1 104 1.5 Aluminum 0.1 0.1 0.1 Manganese 246.8 1.7 Chlorides 190000 162000 155000 135000 99000 201000 Bromide 910530 420 500 410 1060 Sulfate 180 550 950 520 470 200 Nitrate 380 220 120Density 10.13 9.86 9.78 9.58 9.29 10.1 pH 6.3 6.4 6.8 6.7 6.6 5.5

WS6 is a synthetic production water sample.

B. Laboratory Results of ENDURADRIL System i. Viscosifier Agent: FlovisPlus

The sample (i.e., WS1) with highest salinity and hardness was used tomix with different additives (i.e., POWER VIS, FLO-VIS PLUS andviscosifiers). Formulations of the ENDURADRIL systems with FLO-VIS PLUSand POWER VIS are set forth below in Table 14.

TABLE 14 Formulation of ENDURADRIL System with FLOVIS PLUS and POWERVIS. PRODUCT UNITS 1 2 POWER VIS 1 FLO-VIS PLUS ppb 1.5 Caustic Soda ppb1.2 Soda Ash ppb 0.5 0.75

The blend with POWER VIS did not yield. To mix with FLO-VIS PLUS wasused Caustic Soda and Soda Ash to increase pH and treated hardness. Thisblend with FLO-VIS PLUS was cross-linked and FIG. 16 shows sample withFLO-VIS PLUS. The products yield in that water sample very well.Moreover, FIG. 16 is digital images showing top and side views ofproduction water WS1 mixed with 1.5 lb/bbl FLO-VIS PLUS.

ii. Viscosifier Agent: Ditrol

Several formulations of ENDURADRIL system at 9.8 lb/gal densities weremixed using M-I SWACO water-based mud work instruction procedures. Table15 shows chemicals used to formulate ENDURADRIL systems and theirfunctions.

TABLE 15 Functions of Chemicals used to build ENDURADRIL SystemsProducts Function DI-TROL Viscosity / FLC DI-BALANCE Buffer / ViscosityPTS-200 Thermal Stabilizer SAFE-LUBE Lubricant

Hamilton Beach, HB, mixers settled at approximately 3800 rpm wereutilized to mix each RDF samples. At the end of the mixing, the pHvalues were measured with a pH-Meter. Viscosity properties after mixingand after aging (rolled) after 16 hours at 265° F. were measured with aFANN-35 viscometer and were measure coefficient of friction with aLubricity meter.

Twenty-four (24) formulations of ENDURADRIL were mixed and propertiesrecorded. The three first formulations in Table 16 (Products 7, 9 and10) were differentiated by addition of PTS-200 and a SAFE-LUBE.

TABLE 16 ENDURADRIL Formulations and Properties (Products 7, 9 and 10)Product 7 (SW*) 9 (SW*) 10 (SW*) DI-TROL 10 10 10 DI-BALANCE 2 2 2PTS-200 4 4 SAFE-LUBE 2% Properties 7 9 10 BHR AHR BHR AHR BH R AHR 600RPM 31 48 23 34 44 53 300 RPM 22 32 13 22 32 36 200 RPM 18 26 10 17 2729 100 RPM 14 18 6 12 20 21 6 RPM 7 8 3 3 10 10 3 RPM 5 7 2 2 9 9 GELS10″ 6 7 1 3 11 10 GELS 10′ 7 7 2 3 16 12 PV 9 16 10 12 12 17 YP 13 16 310 20 19 CoF 0.154 0.171 pH 8.64 7.93 9.29 SW* is the synthetic water

The PST-200 (i.e., thermal stabilizer) was used to prevent thedegradation of polymers at temperature of 265° F. The SAFE LUBE, alubricant, was used to promote lower coefficient of friction whiledrilling. The DI-TROL (i.e., viscosifier agent) synergistically actedwith DI-BALANCE to provide low end rheology required for hole cleaning.The concentration of DI-TROL was decreased from 10 lb/bbl to 9 lb/bbl inorder to reduce the viscosity of the ENDURADRIL system and complain withequivalent circulation density (hereinafter “ECD”) calculated by VirtualHydraulic Software. The ECD value should be below 12.5 lb.gal fracturegradient of the well. Table 17 captures five (5) formulations andproperties of ENDURADRIL system mixed with 5 production water samples.

TABLE 17 ENDURADRIL Formulations and Properties (Products 20 to 24)Product 20 WS3 21 WS1 22 WS2 23 WS5 24 WS4 DI-TROL 9 9 9 9 9 DI- 2 2 2 22 PTS-200 4 4 4 4 4 SAFE-LUBE 2% 2% 2% 2% 2% Properties 20 21 22 23 24AHR AHR AHR AHR AHR 600 RPM 25 49 29 18 26 300 RPM 19 34 21 12 18 200RPM 16 27 17 10 15 100 RPM 12 21 14 7 11 6 RPM 7 12 7 4 6 3 RPM 6 11 6 35 GELS 10″ 7 11 7 3 6 GELS 10′ 7 11 8 5 7 PV 6 15 8 6 8 YP 13 19 13 6 10CoF 0.137 0.088 0.117 0.137 0.132 pH 8.69 8.45 8.71 8.97 8.95

iii. Coefficient of Friction

The lubricity tester was used to measure coefficient of frictions (alsoreferred to as “CoF” in Table 17) of the fluids. The results werereported as percentage of diminution or augmentation of CoF fresh water.FIG. 17 shows results collected. The WS3, WS4, WS5, WS2 and WS1 werereported on the horizontal axis are name of production water samples,WSs, used to mix ENDURADRIL system. The color code refers are:

-   blue column shows coefficient of friction the sample of production    water;-   red column is the ENDURADRIL mixed with that water;-   green column is ENDURADRIL with lubricant before hot rolling;-   purple column is ENDURADRIL with lubricant after hot rolling.

The vertical axis reports values of CoF measured with Lubriciter TesterModel #. The CoF values of initial production water seemed to be inrelation with concentration of divalent ions present into the system.The addition of DI-TROL (polymer) contributes to decrease the CoF valuecompared to the first measured with production water as shown by FIG. 17(Blue and Red Column). But the addition of 2%v/v of SAFE-LUBE increasedthe CoF of three ENDURADRIL samples before hot rolling (Green Column ofFIG. 17 ). Then the CoF values after dynamic aged decrease back toalmost same values that before addition of SAFE-LUBE. Only with Productsincluding WS5 and WS2 show significate improvement. Based on theseresults, it seems like some reactions occurred between and someproduction waters and SAFE-LUBE. The presumed reaction seems to annulproperties of SAFE-LUBE.

D. Summary

Based on the experimental conditions and results achieved, one or moreof the following conclusions and/or recommendations listed below may bemade:

-   The blend with POWER VIS did not yield; the blend with FLO-VIS PLUS    was cross-linked; and only ENDURADRIL products yield in water sample    very well;-   One recommended ENDURADRIL formulation using production water may be    showed in Table 21.

After 16 hour hot-rolling, ENDURADRIL system has a Plastic Viscosity(PV) and Yield Point (YP) of 8 cP and 13 lb/100 ft² respectively. Thereading at 6 rpm and 3 rpm are 7 and 6, respectively.

The coefficient of friction is lower in ENDURADRIL system (for sampleWS2) than in production water. The CoF of that sample exhibited areduction of 37% compared to production water WS2, and a reduction of52.7% when SAFE-LUBE is added to ENDURADRIL after aging.

Results from Virtual Hydraulics with ENDURADRIL system showed betterhole cleaning than the production water. In order to get hole cleaningindex below 0.25 (very good hole cleaning) the value of ROP recommendedis 25 ft/hr.

TABLE 21 One recommended potential formulation DITROL 9 ppb DI-BALANCE 2ppb PTS-200 4 ppb SAFE-LUBE 2%

While various aspects and examples have been disclosed herein, otheraspects and examples will be apparent to those skilled in the art. Thevarious aspects and examples disclosed herein are for purposes ofillustration and are not intended to be limiting, with the true scopeand spirit being indicated by the following claims.

What is claimed is:
 1. A method of preparing a wellbore fluid comprises:providing an aqueous base fluid, a primary viscosifier, a secondaryviscosifier, a stabilizer and a lubricant, wherein the aqueous basefluid comprises: an inhibitive divalent fluid; and a salt; mixing theaqueous base fluid, the primary viscosifier, the secondary viscosifier,the stabilizer and the lubricant to form the wellbore fluid; and pumpingthe wellbore fluid into a wellbore.
 2. The method of claim 1, furthercomprising: retrieving the wellbore fluid from the wellbore; andfiltering the wellbore fluid for a subsequent use.
 3. The method ofclaim 1, further comprising: formulating at least one cloud pointpolyglycol based shale stabilizer.